The economic value of an oil and gas bearing formation depends on the amount of producible hydrocarbons contained in the subsurface reservoir. This amount of producible hydrocarbons is a function of the formation porosity and permeability.
NMR measurements for formation evaluation yield signals originating from the precessing protons of the fluids in the pore space of the rock. Due to interactions of the fluid molecules with each other or the pore walls, the signal of each proton decays exponentially with a characteristic time T 2 (longitudinal relaxation time).
Permeability is a function of, among other things, the T 2 distribution and the pore size distribution. In sandstones, where porosity and permeability is regular, this relationship is fairly consistent and NMR is a reliable method of characterizing reservoirs. Carbonate reservoirs porosity and permeability are not so well defined as sandstone and the relationship varies with different lithofacies.
Siliciclastic sediments, such as sandstones and shale, develop through the attrition of other rocks. Their grains are sorted prior to deposition. Sandstones and shale are formed of sedimentary particles derived from sources outside the depositional basin. Siliciclastic sediments are relatively stable after deposition. As a result, the pore space in sandstones is mainly intergranular and its complexity depends on the degree of sorting.
Carbonates form in special environments and, in contrast to sandstones, are biochemical in nature. They are essentially autochthonous, as they form very close to the final depositional sites. They are not transported and sorted in the same way as sandstones. Carbonates are usually deposited very close to their source and develop as a result of various processes. Their texture is more dependent on the nature of the skeletal grains than on external influences. Intrabasinal factors control facies development. Reefs, bioherms, and biostroms are example of in-place local deposition where organisms have built wave-resistant structures above the level of adjacent time-equivalent sediments.
Carbonates are characterized by different types of porosity and have unimodal, bimodal, and other complex pore structure distributions. This distribution results in wide permeability variations for the same total porosity, making it difficult to predict their producibility. In this case, long echo trains with a large number of echoes and a long-pre-polarization time may be applicable. Carbonate rock texture produces spatial variations in permeability and capillary bound water volumes.
Carbonates are particularly sensitive to post-depositional diagenesis, including dissolution, cementation, recrystallization, dolomitization, and replacement by other minerals. Calcite can be readily dolomitized, sometimes increasing porosity. Complete leaching of grains by meteoric pore fluids can lead to textural inversion which may enhance reservoir quality through dissolution or occlude reservoirs quality through cementation. Burial compaction fracturing and stylolithification are common diagenetic effects in carbonates, creating high-permeability zones and permeability barriers or baffles, respectively. Diagenesis can cause dramatic changes in carbonate pore size and shape. On a large scale, porosity due to fracturing or dissolution of carbonate rocks can produce “pores” up to the size of caverns.
Given the wide range of origins for carbonate rocks, and the variety of secondary processes which may affect them, it is not surprising that the convoluted pore space of a carbonate may be quite different from that found in siliciclastic sediments. All carbonate sediments are composed of three textural elements: grains, matrix, and cement.
In general, geologists have attempted to classify sedimentary rocks on a natural basis, but some schemes have genetic implications, i.e., knowledge or origin of a particular reservoir rock type (RRT) is assumed.
The relative proportions of the components, among others, can be used to classify carbonate sediments. A widely used classification scheme is proposed by Dunham (see Dunham, “Classification of carbonate rocks according to depositional texture”, in Classification of carbonate rocks—A Symposium, Ham, ed., volume 1, pages 108-121. AAPG Mem., 1962.) In Dunham, carbonates are classified based on the presence or absence of lime mud and grain support. Textures range from grainstone, rudstone, and packstone (grain-supported) to wackestone and mudstone (mud-supported). Where depositional texture is not recognizable, carbonates are classified as boundstone or crystalline. Within these carbonates, the porosity takes many forms, depending on the inherent fabric of the rock and on the types of processes that can occur during and after deposition.
In many carbonates, it is not possible to map the rock texture using conventional logs. Rock texture exerts a strong influence on permeability variations and bound water distributions—important factors in reservoir simulations. For example, while porosity logs may show little change between grainstones, wackestones and mudstones, the capillary-bound water volumes and permeabilities for these rocks may be very different.
Another classification system, by Lucia (see Lucia, Petrophysical parameters estimated from visual description of carbonate rocks: a field classification of pore space. Journal of Petroleum Technology, 35:626-637, March 1983) is based on petrographical attributes and porosity. Dolomites are included in this classification scheme.
Pore type characterization is used in a classification scheme of Choquette & Pray (see P. W. Choquette and L. C. Pray. Geologic nomenclature and classification of porosity in sedimentary carbonates. AAPG Bull., 54:207-250, 1970). Choquette & Pray, in contrast to Dunham, classify carbonates according to fabric and nonfabric pore types. Examples of the former are inter- and intraparticle porosity, while those of the latter are fractures and vugs. Another classification scheme, by Melim et al., differentiates between primary and secondary pore spaces using the description based on classification of Choquette & Pray. Some of the petrographical information obtained using these classifications is used to improve the petrophysical evaluation of the geological formations.
NMR logging tools use large magnets to strongly polarize hydrogen nuclei in water and hydrocarbons as they diffuse about and are contained in the pore space in rocks. When the magnet is removed, the hydrogen nuclei relax. The relaxation time, T 2, depends on the pore-size distribution; larger pores typically have longer relaxation times. Tar and viscous oils relax more quickly than light oil and water. The variations in relaxation time produce a T2 distribution from which fluid components and pore sizes are interpreted. As is well known to those versed in the art, T1, and T2 distributions correlate very well if the diffusion is negligible.
Two standard permeability equations have been established for applications in the oil industry. The Schlumberger-Doll Research (SDR) equation uses simply the geometric mean of the measure T 2 distribution to derive permeability. The Timur-Coates equation uses a T2 cutoff value that divides the T2 distribution into a movable and an irreducible fluid saturation and relates these values to permeability. Other permeability models such as the Kozeny-Carman method may also be used for permeability determination.
Various methods have been proposed to determine formation properties of carbonates using Nuclear Magnetic Resonance. Hidajat et al. (see Hidajat et al., “Study of Vuggy Carbonates using x-ray CT Scanner and NMR”, SPE 77396, 2002) works to improve correlation between NMR T 2 response in carbonate systems, including the contributions of vugs to carbonate permeability. Ramakrishnan et al. (see Ramakrishnan et al., “A Model-based Interpretation Methodology for Evaluating Carbonate Reservoirs”, SPE 71704, 2002) develops an integrated methodology for carbonate interpretation. The methodology of Ramakrishnan parametrizes the pore structure in terms of a multiporosity system of fractures, vugs, inter- and intragranular porosities. NMR data is useful in separating the inter- and intragranular components. The method of Ramakrishnan requires the use of more services than are normally run to provide data.
A summary of the problems in characterizing the properties of carbonate rocks authored by W. Al-Hanai et al is published by the Society of Core Analysists under the title “Carbonate Rocks”. The published U.S. patent application 2003/0231017 provides a summary of the state of art for correlating NMR data with classification of carbonate rocks.
X-ray based analysis of core sample, including computer tomography and Micro-CT instruments, are used in both academia (e.g. O. G. Duliu, “Computer axial tomography in geosciences: an overview.” Earth-Science Reviews, 48, 265-281, 1999; M. A. Knackstedt et al. “Digital Core Laboratory: Properties of reservoir core derived from 3D images” SPE 87009 (2004) and the oil industry (e.g., J, P. Hicks et al., “Distribution of residual oil in heterogeneous carbonate cores using x-ray ct.” SPE Formation Evaluation, 293, 235 ff.) to provide high resolution images and data of sedimentary rocks in 1, 2 or 3D at a micron-scale, so enabling discrimination of pore-size distribution, as well as facilitating the study of multiphase fluid flow within such porous media.
In the light of the above prior art, it is seen as an object improved methods of classifying sedimentary rocks for interpreting log and seismic data.